Drilling wells for oil and gas production conventionally employs longitudinally extending sections, or so-called “strings,” of drill pipe to which, at one end, is secured a drill bit of a larger diameter. The drill bit conventionally forms a bore hole through the subterranean earth formation to a selected depth. Rotary drill bits are commonly used for drilling such bore holes or wells. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag” bit), which typically includes a plurality of cutting elements secured to a face region of a bit body. Referring to FIG. 1, a conventional fixed-cutter rotary drill bit 100 includes a bit body 110 having a face 120 defining a proximal end and comprising generally radially extending blades 130, forming fluid courses 140 therebetween extending to junk slots 150 between circumferentially adjacent blades 130. Bit body 110 may comprise a metal or metal alloy such as steel or a particle-matrix composite material, both as known in the art.
The drill bit includes an outer diameter 155 defining the radius of the wall surface of a bore hole. The outer diameter 155 may be defined by a plurality of gage regions 160, which may also be characterized as “gage pads” herein. Gage regions 160 comprise longitudinally upward (as the drill bit 100 is oriented during use) extensions of blades 130. The gage regions 160 may have wear-resistant inserts and/or coatings, such as hardfacing material, tungsten carbide inserts, natural or synthetic diamonds, or a combination thereof, on radially outer surfaces 170 thereof as known in the art to inhibit excessive wear thereto so that the design borehole diameter to be drilled by the drill bit is maintained over time.
A plurality of cutting elements 180 are conventionally positioned on each of the blades 130. Generally, the cutting elements 180 have either a disk shape or, in some instances, a more elongated, substantially cylindrical shape. The cutting elements 180 commonly comprise a “table” of super-abrasive material, such as mutually bound particles of polycrystalline diamond, formed on a supporting substrate of a hard material, conventionally cemented tungsten carbide. Such cutting elements are often referred to as “polycrystalline diamond compact” (PDC) cutting elements or cutters. The plurality of PDC cutting elements 180 may be provided within cutting element pockets 190 formed in rotationally leading surfaces of each of the blades 130. Conventionally, a bonding material such as an adhesive or, more typically, a braze alloy may be used to secure the cutting elements 180 to the bit body 110.
The bit body 110 of a rotary drill bit 100 is secured to a steel shank 200 having an American Petroleum Institute (API) thread connection 205 for attaching the drill bit 100 to a drill string (not shown), in a conventional manner. A shoulder 210 is typically located on the shank 200 just distal to the thread connection 205. The shoulder 210 is conventionally substantially distant from the proximal portion of the bit body 110 which may affect the bending moment on the shank 200 in some applications, such as in directional drilling. The steel shank 200 typically also includes a plurality of breaker flats 300 configured as a flat surface providing a location which a tool can grasp and rotate the shank 200 to screw into or from the distal end of the drill string.
During drilling operations, the drill bit 100 is positioned at the bottom of a well bore hole and rotated. Drilling fluid is pumped through the inside of the bit body 110, and out through nozzles (not shown) on the face 120. As the drill bit 100 is rotated, the PDC cutting elements 180 scrape across and shear away the underlying earth formation material. The formation cuttings mix with the drilling fluid and pass through the fluid courses 140 and then through the junk slots 150, up through an annular space between the wall of the bore hole and the outer surface of the drill string to the surface of the earth formation.
Often, the bore hole is designed to include one or more deviations or “dog legs” to arrive at the desired ending location from the starting location of the bore hole. Therefore, drilling a bore hole typically requires steering the drill bit through the predetermined path to arrive at the desired location. The total gage length of a drill bit is the axial length from the point where the cutting structure (cutting elements) disposed over the bit face reaches full diameter to the top (trailing end) of the gage section. Conventional drill bits used in steerable assemblies typically employ a short gage length since the side cutting ability of the bit required to initiate a dog leg or deviation is adversely affected by the bit gage length. In other words, if the gage length is longer, a conventional drill bit does not perform well in forming the dog leg.